Pressure Booster for Rotary Steerable System Tool

ABSTRACT

Aspects of the disclosure can relate to a drill assembly that includes a body for receiving a flow of drilling fluid. The body includes a crushing implement and/or a cutting implement and defines a nozzle that allows the drilling fluid to exit the body proximate to the crushing implement and/or the cutting implement. The drill assembly also includes an extendable displacement mechanism coupled with the body and powered by the flow of the drilling fluid. The drill assembly further includes a drive mechanism for driving a pump mechanism disposed in the body. The pump mechanism increases the pressure of a fraction of the flow of the drilling fluid, and the fraction of the flow of the drilling fluid is furnished to the extendable displacement mechanism.

BACKGROUND

Oil wells are created by drilling a hole into the earth using a drillingrig that rotates a drill string (e.g., drill pipe) having a drill bitattached thereto. The drill bit, aided by the weight of pipes (e.g.,drill collars) cuts into rock within the earth. Drilling fluid (e.g.,mud) is pumped into the drill pipe and exits at the drill bit. Thedrilling fluid may be used to cool the bit, lift rock cuttings to thesurface, at least partially prevent destabilization of the rock in thewellbore, and/or at least partially overcome the pressure of fluidsinside the rock so that the fluids do not enter the wellbore. Rotarysteerable systems (RSS) can be used for directional drilling. Thesesystems employ down hole equipment that responds to commands (e.g., fromsurface equipment) and steers into a desired direction. For example,pistons may be used to generate force against a borehole wall or tocause angular displacement of one steerable system component withrespect to another to cause a drill bit to move in the desired directionof deviation.

SUMMARY

Aspects of the disclosure can relate to a drill assembly that includes abody for receiving a flow of drilling fluid. The body includes acrushing implement and/or a cutting implement and defines a nozzle thatallows the drilling fluid to exit the body proximate to the crushingimplement and/or the cutting implement. The drill assembly also includesan extendable displacement mechanism coupled with the body and poweredby the flow of the drilling fluid. The drill assembly further includes adrive mechanism for driving a pump mechanism disposed in the body. Thepump mechanism increases the pressure of a fraction of the flow of thedrilling fluid, and the fraction of the flow of the drilling fluid isfurnished to the extendable displacement mechanism.

Other aspects of the disclosure can relate to a drill assembly thatincludes a body for receiving a flow of drilling fluid. The bodyincludes a crushing implement and/or a cutting implement and defines anozzle that allows the drilling fluid to exit the body proximate to thecrushing implement and/or the cutting implement. The drill assembly alsoincludes an extendable displacement mechanism coupled with the body andpowered by the flow of the drilling fluid. The drill assembly furtherincludes a pressure booster disposed in the body. The pressure boosterincreases the pressure of a fraction of the flow of the drilling fluid,and the fraction of the flow of the drilling fluid is furnished to theextendable displacement mechanism.

Also, aspects of the disclosure can relate to a method that includessupplying a portion of a flow of drilling fluid to a nozzle proximate toa crushing implement and/or a cutting implement. The method alsoincludes receiving the flow of drilling fluid at a drive mechanism fordriving a pump mechanism to increase the pressure of a fraction of theflow of the drilling fluid. The method further includes furnishing thefraction of the flow of the drilling fluid to an extendable displacementmechanism powered by the flow of the drilling fluid.

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

FIGURES

Embodiments of a pressure booster for a rotary steerable system tool aredescribed with reference to the following figures. The same numbers areused throughout the figures to reference like features and components.

FIG. 1 illustrates an example system in which embodiments of a pressurebooster for a rotary steerable system tool can be implemented;

FIG. 2 illustrates an example rotary steerable system tool with apressure booster in accordance with one or more embodiments;

FIG. 3 illustrates an example pressure booster for a rotary steerablesystem tool, such as the rotary system tool illustrated in FIG. 1, inaccordance with one or more embodiments;

FIG. 4 illustrates an example pump mechanism for a pressure booster fora rotary steerable system tool, such as the rotary system toolillustrated in FIG. 1, in accordance with one or more embodiments; and

FIG. 5 illustrates example method(s) for pressure boosting for a rotarysteerable system tool in accordance with one or more embodiments.

DETAILED DESCRIPTION

FIG. 1 depicts a wellsite system 100 in accordance with one or moreembodiments of the present disclosure. The wellsite can be onshore oroffshore. A borehole 102 is formed in subsurface formations bydirectional drilling. A drill string 104 extends from a drill rig 106and is suspended within the borehole 102. In some embodiments, thewellsite system 100 implements directional drilling using a rotarysteerable system (RSS). For instance, the drill string 104 is rotatedfrom the surface, and down hole devices move the end of the drill string104 in a desired direction. The drill rig 106 includes a platform andderrick assembly positioned over the borehole 102. In some embodiments,the drill rig 106 includes a rotary table 108, kelly 110, hook 112,rotary swivel 114, and so forth. For example, the drill string 104 isrotated by the rotary table 108, which engages the kelly 110 at theupper end of the drill string 104. The drill string 104 is suspendedfrom the hook 112 using the rotary swivel 114, which permits rotation ofthe drill string 104 relative to the hook 112. However, thisconfiguration is provided by way of example only and is not meant tolimit the present disclosure. For instance, in other embodiments a topdrive system is used.

A bottom hole assembly (BHA) 116 is suspended at the end of the drillstring 104. The bottom hole assembly 116 includes a drill bit 118 at itslower end. In embodiments of the disclosure, the drill string 104includes a number of drill pipes 120 that extend the bottom holeassembly 116 and the drill bit 118 into subterranean formations.Drilling fluid (e.g., mud) 122 is stored in a tank and/or a pit 124formed at the wellsite. The drilling fluid can be water-based,oil-based, and so on. A pump 126 displaces the drilling fluid 122 to aninterior passage of the drill string 104 via, for example, a port in therotary swivel 114, causing the drilling fluid 122 to flow downwardlythrough the drill string 104 as indicated by directional arrow 128. Thedrilling fluid 122 exits the drill string 104 via ports (e.g., courses,nozzles) in the drill bit 118, and then circulates upwardly through theannulus region between the outside of the drill string 104 and the wallof the borehole 102, as indicated by directional arrows 130. In thismanner, the drilling fluid 122 cools and lubricates the drill bit 118and carries drill cuttings generated by the drill bit 118 up to thesurface (e.g., as the drilling fluid 122 is returned to the pit 124 forrecirculation).

In some embodiments, the bottom hole assembly 116 includes alogging-while-drilling (LWD) module 132, a measuring-while-drilling(MWD) module 134, a rotary steerable system 136, a motor, and so forth(e.g., in addition to the drill bit 118). The logging-while-drillingmodule 132 can be housed in a drill collar and can contain one or anumber of logging tools. It should also be noted that more than one LWDmodule and/or MWD module can be employed (e.g. as represented by anotherlogging-while-drilling module 138). In embodiments of the disclosure,the logging-while drilling modules 132 and/or 138 include capabilitiesfor measuring, processing, and storing information, as well as forcommunicating with surface equipment, and so forth.

The measuring-while-drilling module 134 can also be housed in a drillcollar, and can contain one or more devices for measuringcharacteristics of the drill string 104 and drill bit 118. Themeasuring-while-drilling module 134 can also include components forgenerating electrical power for the down hole equipment. This caninclude a mud turbine generator (also referred to as a “mud motor”)powered by the flow of the drilling fluid 122. However, thisconfiguration is provided by way of example only and is not meant tolimit the present disclosure. In other embodiments, other power and/orbattery systems can be employed. The measuring-while-drilling module 134can include one or more of the following measuring devices: aweight-on-bit measuring device, a torque measuring device, a vibrationmeasuring device, a shock measuring device, a stick slip measuringdevice, a direction measuring device, an inclination measuring device,and so on.

In embodiments of the disclosure, the wellsite system 100 is used withcontrolled steering or directional drilling. For example, the rotarysteerable system 136 is used for directional drilling. As used herein,the term “directional drilling” describes intentional deviation of thewellbore from the path it would naturally take. Thus, directionaldrilling refers to steering the drill string 104 so that it travels in adesired direction. In some embodiments, directional drilling is used foroffshore drilling (e.g., where multiple wells are drilled from a singleplatform). In other embodiments, directional drilling enables horizontaldrilling through a reservoir, which enables a longer length of thewellbore to traverse the reservoir, increasing the production rate fromthe well. Further, directional drilling may be used in vertical drillingoperations. For example, the drill bit 118 may veer off of a planneddrilling trajectory because of the unpredictable nature of theformations being penetrated or the varying forces that the drill bit 118experiences. When such deviation occurs, the wellsite system 100 may beused to guide the drill bit 118 back on course.

FIG. 2 depicts a drill assembly 200 that can be used with, for example,a wellsite system (e.g., the wellsite system 100 described withreference to FIG. 1). For instance, the drill assembly 200 can comprisea bottom hole assembly suspended at the end of a drill string (e.g., inthe manner of the bottom hole assembly 116 suspended from the drillstring 104 depicted in FIG. 1). In some embodiments, the drill assembly200 is implemented using a drill bit. However, this configuration isprovided by way of example only and is not meant to limit the presentdisclosure. In other embodiments, different working implementconfigurations are used. Further, use of drill assemblies 200 inaccordance with the present disclosure is not limited to wellsitesystems described herein. Drill assemblies 200 can be used in othervarious cutting and/or crushing applications, including earth boringapplications employing rock scraping, crushing, cutting, and so forth.

The drill assembly 200 includes a body 202 for receiving a flow ofdrilling fluid. The body 202 comprises one or more crushing and/orcutting implements, such as conical cutters and/or bit cones havingspiked teeth (e.g., in the manner of a roller-cone bit). In thisconfiguration, as the drill string is rotated, the bit cones roll alongthe bottom of the borehole in a circular motion. As they roll, new teethcome in contact with the bottom of the borehole, crushing the rockimmediately below and around the bit tooth. As the cone continues toroll, the tooth then lifts off the bottom of the hole and ahigh-velocity drilling fluid jet strikes the crushed rock chips toremove them from the bottom of the borehole and up the annulus. As thisoccurs, another tooth makes contact with the bottom of the borehole andcreates new rock chips. In this manner, the process of chipping the rockand removing the small rock chips with the fluid jets is continuous. Theteeth intermesh on the cones, which helps clean the cones and enableslarger teeth to be used. A drill assembly 200 comprising a conicalcutter can be implemented as a steel milled-tooth bit, a carbide insertbit, and so forth. However, roller-cone bits are provided by way ofexample only and are not meant to limit the present disclosure. In otherembodiments, a drill assembly 200 is configured differently. Forexample, the body 202 of the bit comprises one or more polycrystallinediamond compact (PDC) cutters that shear rock with a continuous scrapingmotion.

In embodiments of the disclosure, the body 202 of the drill assembly 200defines one or more nozzles 204 that allow the drilling fluid to exitthe body 202 (e.g., proximate to the crushing and/or cuttingimplements). The nozzles 204 allow drilling fluid pumped through, forexample, a drill string to exit the body 202. For example, as discussedwith reference to FIG. 1, drilling fluid 122 is furnished to an interiorpassage of drill string 104 by pump 126 and flows downwardly throughdrill string 104 to drill bit 118 of bottom hole assembly 116, which canbe implemented using a drill assembly 200. Drilling fluid 122 then exitsdrill string 104 via nozzles in drill bit 118 (e.g., via nozzles 204),and circulates upwardly through the annulus region between the outsideof drill string 104 and the wall of borehole 102. In this manner, rockcuttings can be lifted to the surface, destabilization of the rock inthe wellbore can be at least partially prevented, the pressure of fluidsinside the rock can be at least partially overcome so that the fluids donot enter the wellbore, and so forth.

The drill assembly 200 also includes one or more extendable displacementmechanisms 206, such as a piston mechanism that can be selectivelyactuated by an actuator 208 to displace a pad 210 toward, for instance,a borehole wall to cause the drill assembly 200 to move in a desireddirection of deviation. In embodiments of the disclosure, thedisplacement mechanism 206 is actuated by drilling fluid routed throughthe body 202 of the drill assembly 200. For example, as discussed withreference to FIG. 1, drilling fluid 122 is used to move a piston, whichchanges the orientation of the drill bit 118 (e.g., changing thedrilling axis orientation with respect to a longitudinal axis of thebottom hole assembly 116). The displacement mechanism 206 may beemployed to control a directional bias and/or an axial orientation ofthe drill assembly 200. Displacement mechanisms 206 may be arranged, forexample, to point the drill assembly 200 or to push the drill assembly200. In some embodiments, the drill assembly 200 is deployed by adrilling system using a rotary steerable system that rotates with anumber of displacement mechanisms 206 (e.g., the rotary steerable system136 described with reference to FIG. 1). It should be noted that such arotary steerable system can be used in conjunction with stabilizers,such as non-rotating stabilizers, and so on.

Increased steering from the drill assembly 200 can in part be achievedif there is more force available from the actuator 208 to drive the bitin the desired direction. However, the force available to a down holehydraulic actuator may be constrained by the pressure available at theend of the drill string, the area of an active piston, and so forth.Thus, in an application of limited physical size (e.g., where the sizeof a piston may not be increased) for example, the working fluidpressure can be raised to increase the available force from the actuator208. As described herein, pressure boosting (e.g., using a large volumeof working fluid to increase the pressure of a much smaller volume ofworking fluid) is used to increase the available force provided by theactuator 208. For example, in some embodiments, the flow of the majorityof the drilling fluid through the body 202 of the drill assembly 200 andto the nozzles 204 is used to drive a pressure booster 212 thatincreases the pressure of a fraction of the flow of the drilling fluid.For instance, a high pressure flow of drilling fluid is furnished to anRSS tool (e.g., to displace the pad 210 of the drill assembly 200). Inthis manner, more force can be generated on the pad 210 because of thehigher pressure of the drilling fluid (e.g., with respect to using thepressure of the drilling fluid on the pad 210 without a pressure booster212). In some embodiments, one or more valves are used to distribute theflow of the drilling fluid to the actuator 208. For example, a valve canbe coupled with a controller (e.g., via wired connection, a wirelessconnection, and so forth) to selectively actuate the displacementmechanism 206.

In embodiments of the disclosure, the pressure booster 212 comprises adrive mechanism 214 for driving a pump mechanism 216. For example, asshown in FIG. 2, the drive mechanism 214 comprises an axial flow turbine218 (e.g., employing a turbine stator 220 and a turbine rotor 222). Theturbine rotor 222 is coupled with the pump mechanism 216, which can beimplemented using a compressor (e.g., a centrifugal compressor 224). Inthis example, at least substantially the entire flow of drilling fluidthrough the body 202 (e.g., to the nozzles 204) passes through theturbine 218, driving the centrifugal compressor 224. This flow ofdrilling fluid is indicated by directional arrows 226. The centrifugalcompressor 224 is positioned upstream from the turbine 218 with respectto the flow of the drilling fluid and takes its inlet charge (e.g., asmall percentage of the total flow of drilling fluid) from before theturbine 218. The inlet charge is represented by directional arrows 228.However, this configuration is provided by way of example only and isnot meant to limit the present disclosure. In other embodiments, thepump mechanism 216 is positioned behind the drive mechanism 214 (e.g.,downstream from the drive mechanism 214 with respect to the flow of thedrilling fluid). It should be noted that in such a configuration, thepump mechanism 216 may use a higher pressure ratio and the volume ofhigh pressure fluid may be less.

With reference to FIG. 3, in some embodiments the drive mechanism 214employs a multi-stage turbine 230. For example, two or more turbines 218are used to drive the pump mechanism 216 (e.g., using multiple,concentric turbine shafts, and so forth). In some embodiments, one ormore of the turbines 218 comprises an axial turbine 232. In otherembodiments, one or more of the turbines comprises a radial turbine 234.However, these turbine configurations are provided by way of exampleonly and are not meant to limit the present disclosure. In otherembodiments, different turbine configurations are used with the drillassembly 200. It should be noted that other pump mechanisms 216 can alsobe used with the drill assembly 200, including positive displacementpumps for higher pressure ratios, and so forth. For example, withreference to FIG. 4, the pump mechanism 216 can include a roots blowerpump 236, a piston pump 238, a screw feed pump 240, a vane pump 242, andso forth. Further, the pump mechanism 216 can employ multiple stages(e.g., using multiple compressor stages, and so on).

In some embodiments, a force maintainer is used to maintain the pressureof the drilling fluid to the drill assembly 200 (e.g., for long drillstrings). In some embodiments, multiple pistons are used for thedisplacement mechanism 206. For example, a smaller piston is used togenerate force on a larger piston, which in turn is used to displace thepad 210. It should be noted that while the pressure booster anddisplacement mechanism 206 are shown proximate to the bit of the drillassembly 200 in FIG. 2, one or more of the displacement mechanism 206,the drive mechanism 214, the pump mechanism 216, and so forth, can bepositioned at various locations along a drill string, a bottom holeassembly, and so on. For example, in some embodiments, the displacementmechanism 206 is positioned in the rotary steerable system 136, while inother embodiments, the displacement mechanism 206 is positioned at ornear the end of the bottom hole assembly 116 (e.g., proximate to thedrill bit 118). In some embodiments, the drill assembly 200 includes oneor more filters that filter the drilling fluid (e.g., upstream of thedrive mechanism 214 and/or the pump mechanism 216 with respect to theflow of the drilling fluid).

Referring now to FIG. 5, a procedure 500 is described in an exampleembodiment in which pressure to a displacement mechanism of a tool isboosted. At block 510, at least a portion of a flow of drilling fluid,such as drilling fluid 122, is supplied to a nozzle, such as nozzle 204,proximate to at least one of a crushing implement or a cuttingimplement, such as a conical cutter, a bit cone, and so forth, of adrill bit 118. At block 520, the flow of drilling fluid is received at adrive mechanism, such as the drive mechanism 214, for driving a pumpmechanism, such as the pump mechanism 216, to increase the pressure of afraction of the flow of the drilling fluid, such as the flow of drillingfluid indicated by directional arrows 228. At block 530, the fraction ofthe flow of the drilling fluid is furnished to a displacement mechanism,such as the extendable displacement mechanism 206, powered by the flowof the drilling fluid.

Although only a few example embodiments have been described in detailabove, those skilled in the art will readily appreciate that manymodifications are possible in the example embodiments without materiallydeparting from PRESSURE BOOSTER FOR ROTARY STEERABLE SYSTEM TOOL.Features shown in individual embodiments referred to above may be usedtogether in combinations other than those which have been shown anddescribed specifically. Accordingly, all such modifications are intendedto be included within the scope of this disclosure as defined in thefollowing claims. In the claims, means-plus-function clauses areintended to cover the structures described herein as performing therecited function and not only structural equivalents, but alsoequivalent structures. Thus, although a nail and a screw may not bestructural equivalents in that a nail employs a cylindrical surface tosecure wooden parts together, whereas a screw employs a helical surface,in the environment of fastening wooden parts, a nail and a screw may beequivalent structures. It is the express intention of the applicant notto invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of theclaims herein, except for those in which the claim expressly uses thewords ‘means for’ together with an associated function.

What is claimed is:
 1. A drill assembly comprising: a body for receivinga flow of drilling fluid and comprising at least one of a crushingimplement or a cutting implement, the body defining a nozzle allowingthe drilling fluid to exit the body proximate to the at least one of thecrushing implement or the cutting implement; an extendable displacementmechanism coupled with the body and powered by the flow of the drillingfluid; and a drive mechanism for driving a pump mechanism disposed inthe body for increasing the pressure of a fraction of the flow of thedrilling fluid, where the fraction of the flow of the drilling fluid isfurnished to the extendable displacement mechanism.
 2. The drillassembly as recited in claim 1, wherein the drive mechanism comprises aturbine.
 3. The drill assembly as recited in claim 2, wherein theturbine comprises a multi-stage turbine.
 4. The drill assembly asrecited in claim 2, wherein the turbine comprises at least one of anaxial turbine or a radial turbine.
 5. The drill assembly as recited inclaim 1, wherein the pump mechanism comprises a compressor.
 6. The drillassembly as recited in claim 1, wherein the pump mechanism comprises atleast one of a roots blower pump, a piston pump, a screw feed pump, or avane pump.
 7. The drill assembly as recited in claim 1, wherein the pumpmechanism is positioned upstream from the drive mechanism.
 8. The drillassembly as recited in claim 1, wherein at least substantially theentire flow of drilling fluid through the body passes through the drivemechanism.
 9. A drill assembly comprising: a body for receiving a flowof drilling fluid and comprising at least one of a crushing implement ora cutting implement, the body defining a nozzle allowing the drillingfluid to exit the body proximate to the at least one of the crushingimplement or the cutting implement; an extendable displacement mechanismcoupled with the body and powered by the flow of the drilling fluid; anda pressure booster disposed in the body for increasing the pressure of afraction of the flow of the drilling fluid, where the fraction of theflow of the drilling fluid is furnished to the extendable displacementmechanism.
 10. The drill assembly as recited in claim 9, wherein thepressure booster comprises a drive mechanism for driving a pumpmechanism.
 11. The drill assembly as recited in claim 10, wherein thedrive mechanism comprises a turbine.
 12. The drill assembly as recitedin claim 11, wherein the turbine comprises a multi-stage turbine. 13.The drill assembly as recited in claim 11, wherein the turbine comprisesat least one of an axial turbine or a radial turbine.
 14. The drillassembly as recited in claim 10, wherein the pump mechanism comprises acompressor.
 15. The drill assembly as recited in claim 10, wherein thepump mechanism comprises at least one of a roots blower pump, a pistonpump, a screw feed pump, or a vane pump.
 16. The drill assembly asrecited in claim 9, wherein the pump mechanism is positioned upstreamfrom the drive mechanism.
 17. The drill assembly as recited in claim 9,wherein at least substantially the entire flow of drilling fluid throughthe body passes through the drive mechanism.
 18. A method comprising:supplying at least a portion of a flow of drilling fluid to a nozzleproximate to at least one of a crushing implement or a cuttingimplement; receiving the flow of drilling fluid at a drive mechanism fordriving a pump mechanism to increase the pressure of a fraction of theflow of the drilling fluid; furnishing the fraction of the flow of thedrilling fluid to an extendable displacement mechanism powered by theflow of the drilling fluid.
 19. The method as recited in claim 18,wherein the drive mechanism comprises a turbine.
 20. The method asrecited in claim 18, wherein the pump mechanism comprises a compressor.